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The Banshanping granitoid rocks distribute in the east of the North Qinling orogenic belt. It is a diorite‐quartz diorite‐granodiorite‐granite series, spreading in a NW‐SE direction, and intrudes into the Erlangping Group. The SiO2 content ranges from 57.04% to 76.56%, Na2O from 2.05% to 4.65%, K2O from 0.84% to 3.40%. Major element characteristics indicate that Banshanping granitoid rocks have properties of I type granotoids. SREE ranges from 36.51 ppm to 473.25 ppm, and LREE/HREE ratios lie between 3.95 and 22.18. Negative Eu anomalies are not obvious in most samples, though there are obvious Nb, P and Ti positive anomalies. The zircon LA‐ICP‐MS ages of Banshangping granitoid rocks are 496.0±8.1 Ma–486.9±9.3 Ma. Hf isotope shows that 176Hf/177Hf ratios range from 0.282721 to 0.282876, εHf(t) values from 8.5 to 14, all positive, and corresponding modal ages (TDM2) range from 559 Ma to 908 Ma. Based on Hf isotope characteristics and existing Sm‐Nd and Rb‐Sr isotope data, we consider that the Banshanping granitoid rocks originate from mantle‐derived material, i.e. the igneous rocks that formed in Neoproterozoic, and there may be a certain amount of crust‐derived material during the formation of Banshanping granitoid rocks.

The accurate identification of gas channeling channels during foam-assisted oxygen-reduced air flooding (FAORAF) and the analysis of the main controlling factors are essential to propose reasonable and effective countermeasures to enhance oil recovery (EOR). However, there are few comprehensive studies on identifying gas channeling channels, the influencing factors, and the corresponding plugging EOR systems in FAORAF. The channeling channels of the injection and production wells of the Changqing Oilfield, China, under varying development schemes are identified utilizing fuzzy membership function theory in this work to obtain their primary distribution. The characteristics and influence factors of gas channeling channels are analyzed by numerical simulation using CMG. The recovery performance of each foam blocking system is evaluated by twin-tube sand pack models. As well, based on the features of reservoir fractures, a new gel-enhanced foam plugging system is developed. The results show that channeling channels chiefly develop along NE 60–70° and that foam could reduce gas channeling. Natural and artificial fractures are the principal factors causing gas channeling, followed by the injection method and gas injection rate. Under the premise of the injection and migration efficiency, the optimal gel system is a 0.1% HPAM + 0.1% organic chromium crosslinking agent. The addition of gel increases the viscosity of the liquid phase and strengthens the mechanical strength of the foam liquid film. At a permeability ratio of 12, the recovery factors of the binary plugging systems composed of microspheres, PEG, and gel combined with foam are 40.89%, 45.85%, and 53.33%, respectively. The movable gel foam system has a short breaking time (only 18 days) and a recovery factor of about 40% at a permeability ratio of 20. To be suitable for oil reservoirs with microfractures, an improved ternary gel foam system—0.1% HPAM + 0.1% chromium crosslinking agent + 0.05–0.1% nano-SiO2—is developed. Compared with the binary gel foam system, the recovery rate of the new nano-SiO2 gel foam system after 15 days of ageing using the core splitting test is 25.24% during the FAORAF process, increasing by 12.38%.

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